Multi-Well Interference Testing and In-Situ Reservoir Behavior Characterization

ABSTRACT

Using multi-well testing, operators can characterize a reservoir and its in-situ behavior using direct measurements of reservoir pressures. One or more impulses are generated in an impulse well or location using production, injections, or the like. Downhole pressure tools directly measure pressure responses at various observations wells in the reservoir. Based on the magnitudes of the responses, the distances between the wells, the time lag between responses, and other variables, operators can characterize the pressure distribution of the reservoir and various features, such as the connectivity and extent of the reservoir, barriers, faults, obstructions, pools, communication paths, layer contacts, and well spacing efficiency.

CROSS-REFERENCE TO RELATED APPLICATIONS

This is a non-provisional of U.S. Provisional Appl. Ser. No. 61/321,769, filed 7 Apr. 2010, which is incorporated herein by reference and to which priority is claimed.

BACKGROUND

Wells are drilled in an earth formation to extract the gas, water, and/or hydrocarbons from a reservoir. To know where to drill the wells and extract the fluids, operators may use seismic data, test wells, well logs, and other techniques available in the art. In general, the reservoir can be viewed as a large pressure network. Knowing the distribution of pressure in a reservoir can, therefore, be very beneficial for operators as they plan and perform production operations in various wells in the reservoir.

One technique for determining reservoir pressure uses a repeat formation tester pressure survey. In such a survey, a well-to-well interference test is conducted between a pulse well and an observation well. Details of this technique are disclosed in Lasseter et al., “Interpreting an RFT-Measured Pulse Test with a Three-Dimensional Simulator,” SPE Formation Evaluation (March 1988). Such interference well testing can take an extended period of time for a measurable pressure variation to occur in an adjacent observation well.

What is needed is a way to characterize a reservoir in real-time using a cluster of existing wells to determine features of the reservoir so operators can improve production and other operations related to the reservoir.

SUMMARY

Methods and systems for reservoir characterization use downhole pressure devices deployed in wells penetrating a reservoir. Initially, the pressure devices obtain reference pressure measurements, which are then used to scale later-obtained pressure responses. The arrangement of pressure devices, depths, wells and proposed pressure impulse can also be verified prior to performing a pressure impulse. For example, processing that performs reservoir simulation based on input data can determine if magnitudes of pressure responses of the downhole pressure devices will fall within acceptable limits.

To begin characterizing the reservoir, at least one pressure impulse is initiated at an impulse time in at least one of the wells penetrating the reservoir. This impulse can be initiated by producing a pressure drop in the well, performing production from the well, producing a pressure spike in the well, drilling in the well with drilling fluid, injecting treatment fluid in the well, and performing a test in the well. In response to the impulse, the downhole pressure devices coupled to the formations in the wells obtain pressure responses at response times. In turn, the data is communicated to a central unit using communication equipment. The communication can be done in real-time using satellite, wireless, wired, or any other known technology. Alternatively, the pressure responses, response times, and other data can be stored in memory of the downhole pressure devices for later retrieval and processing. Overall, communication of the data can be performed in a number of ways, including real-time transmission, transferring data after recovering downhole memory tools, making a wet connect to downhole memory tools for electronic transmission, downloading data through acoustic or optical data transmission with downhole memory tools, or the like.

Using the obtained data, processing equipment at the central unit processes the pressure responses and the response times and characterizes the reservoir based on the data. In addition to the obtained pressure responses and times, the central unit can use other data about the reservoir, including depths of the downhole pressure devices, seismic data of the reservoir, information from formation cores of the wells, locations of the wells having the downhole pressure devices, known fluid types in the wells, previous production data of the wells, previous logging data of the wells, and reservoir simulations.

Once the data is processed, the processing can determine or verify a number of features of the reservoir, including the reservoir's extent, boundaries, communication, and reserve estimates. Likewise, the processing can determine the pressure distribution in the reservoir and characterize barriers, faults, pools, permeable zones, communication paths, obstructions, and other features of the reservoir.

As one example, the processing can determine that at least one of the downhole pressure devices has failed to obtain at least one of the pressure responses, even though this well may be producing. This may be used to characterize an obstruction in the reservoir between the well in which the impulse was initiated and the downhole pressure device in one of the other wells.

As another example, the processing can determine that a first of the downhole pressure devices in a first well has obtained pressure responses while a second downhole pressure device in a second well has failed to obtain pressure responses. From this, the processing can characterize the reservoir as having a first pool associated with the first well and having a second pool associated with the second well.

As another example, the processing can determine that a downhole pressure device in a first well has obtained a first magnitude of pressure responses within a first time interval and a second magnitude of pressure responses within a second time interval. From this, the processing can characterize the reservoir as having a first communication path for the first time interval and a second communication path for the second time interval. These two paths indicate different links in the communication of the reservoir between the well having the impulse and the well having the pressure device.

As yet another example, the downhole pressure devices can be deployed at different depths than the depth at which the pressure impulse is initiated. After obtaining responses and times from the initiated impulse, the processing can calculate speeds of pressure wave propagation for the pressure responses of the downhole pressure devices. Based on the calculated speeds, the processing can characterize the reservoir by determining a characteristic of one or more fluid layers, contacts, or the like in the reservoir.

The foregoing summary is not intended to summarize each potential embodiment or every aspect of the present disclosure.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 illustrates a well having a reservoir pressure system according to certain teachings of the present disclosure.

FIG. 2A shows several adjacent wells in a reservoir having various arrangements of observer locations and an impulse location for characterizing features of the reservoir.

FIG. 2B is a process for characterizing features of a reservoir using the disclosed reservoir pressure system.

FIG. 3A shows a plan view of a first arrangement of adjacent wells in a reservoir having various observer locations and an impulse location for characterizing features of the reservoir.

FIG. 3B shows an example graph of reservoir pressure versus time from the arrangement in FIG. 3A.

FIG. 4A shows a plan view of a second arrangement of adjacent wells in a reservoir having various observer and impulse locations as well as a barrier in the reservoir.

FIG. 4B shows an example graph of reservoir pressure versus time from the arrangement in FIG. 4A.

FIG. 5A shows a plan view of a third arrangement of adjacent wells in a reservoir having various observer and impulse locations as well as isolated pools.

FIG. 5B shows an example graph of reservoir pressure versus time from the arrangement in FIG. 5A.

FIG. 6A shows a plan view of a fourth arrangement of adjacent wells in a reservoir having various observer and impulse locations as well as isolated pools with communication paths therebetween.

FIG. 6B shows an example graph of reservoir pressure versus time from the arrangement in FIG. 6A.

FIG. 7A shows a side view of a fifth arrangement of adjacent wells in a reservoir having various observer and impulse locations as well as a dome with layers.

FIG. 7B shows an example graph of reservoir pressure versus time from the arrangement in FIG. 7A.

FIG. 8A shows a plan view of a sixth arrangement of adjacent wells in a reservoir having various observer and impulse locations as well as an obstruction with communication paths therearound.

FIG. 8B shows an example graph of reservoir pressure versus time from the arrangement in FIG. 8A.

FIG. 9A shows a plan view of a seventh arrangement of adjacent wells in a reservoir having various observer and impulse locations.

FIG. 9B shows an example graph of reservoir pressure versus time from the arrangement in FIG. 9A.

DETAILED DESCRIPTION

FIG. 1 illustrates a well 10 having a reservoir pressure system 100 according to certain teachings of the present disclosure. The system 100 has a downhole pressure device or tool 110 that deploys in the well 10 and couples with the adjacent formation. In general, the well 10 may be an open hole, but the system 100 can be used with other well configurations. If the well 10 has a horizontal section, the tool 110 can be assisted by a non-gravity assisted conveyance 126. Otherwise, the tool 110 can be conveyed by a wireline 124, which in turn can be used for communication purposes. However, the tool 110 could be deployed in the well 10 and left in place without the wireline 124 connected, in which case memory on the tool 110 may record the desired measurements.

The downhole tool 110 can be a formation pressure measurement tool, such as disclosed in U.S. Pat. Pub. No. 2008/0173083, filed 24 Jan. 2007, which is incorporated herein by reference. However, the tool 110 can be any suitable tool used for wireline formation testing, production logging, Logging While Drilling/Measurement While Drilling (LWD/MWD), etc.

For example, the downhole tool 110 can be a Compact™ Formation Pressure Tester (MFT) available from Weatherford that can be set to record pressure measurements using a wireline 124 or the like. Optionally, the tool 110 can be set using a logging unit, and the wireline 124 can be anchored to wellhead. The logging unit can be removed, and the well 10 can be sealed off at the surface. To obtain data, the wireline 124 can be connected to a remote data unit.

At the surface, for example, a cable clamp 120 and seal mechanism 122 can hold the wireline 124. To relay data for processing, communication equipment can communicate with the downhole tools 110 in real-time and can send data in real-time using satellite, wireless, wired, or any other known technology. For example, a mobile logging unit 135 can connect by a quick connect 128 to the wireline 124 to obtain formation pressure measurements in real-time. Alternatively, a logging skid or remote data unit 130 can connect to the wireline 124. In either case, the unit 130/135 can send real-time data transmissions of the formation pressure measurements to a centralized location 140 having its own data processing capabilities and equipment, such as computers, databases, user interfaces, and the like. Thus, this processing equipment at the centralized location 140 communicatively couples to the communication equipment 130/135 and receives the data to be processed to characterize the reservoir. The received data can generally include the time that the impulse was initiated, the pressure responses and times of the downhole pressure devices 110, and other suitable data as detailed herein.

With the tool 110 deployed downhole and coupled to the formation, the tool 110 can measure perturbations or changes in the formation's pressure. These perturbations are produced in an adjacent well passing through the reservoir. As shown in FIG. 2A, for example, several adjacent wells 10A-C may be already drilled into a reservoir. Advantageously, the system 100 can be used in these existing wells of the reservoir so that new wells do not need to be drilled.

Each of these wells 10A-C is equipped with a downhole tool 110A-C at an observation location O_(A-C) for obtaining formation pressure measurements from the reservoir in their respective wells 10A-C. An impulse is induced in the reservoir in at least one of the wells (i.e., impulse well 10A in this example). Pressure pulses or perturbations from this impulse then travel through the reservoir in the formation, and the downhole tools 110A-C detect the formation pressures at their locations in real-time.

In general, the impulse can be provided by a variety of activities. For example, production in the well 10A can induce an impulse (i.e., pressure drop) in the reservoir to be detected at the tools 100A-C. Alternatively, drilling in the well 10A with drilling mud and the like can induce the impulse (i.e., pressure spike). In another example, stimulating the well with a frac operation or an injection operation can also produce the impulse. Likewise, testing in the well 10A, such as pore pressure or well production tests, can produce the impulse needed.

A. Process

The overall process 150 of producing the impulse and detecting formation pressures of the reservoir is shown in FIG. 2B. Using the existing wells (10A-C) in a reservoir, operators select a cluster of observation locations (O_(A-C)) and one or more impulse locations (Block 152). The observation locations (O_(A-C)) can be situated at horizontal or vertical points in the given wells (10), and the same well 10 can have one or more observation locations (O_(A-C)). To simplify data processing, at least one impulse location (I) is used at a given time, although multiple wells (10) could have impulse locations (I) and a given well (10) may have multiple impulse locations (I) that act simultaneously or separately.

Each consideration of how the observation and impulse locations (I, O) are set up in wells (10) of a reservoir depends on what wells (10) are existing, what expected characteristics the reservoir has, and what information is desired from the characterization, as well as other considerations that depend on the implementation. In selecting locations, operators may use existing seismic information, well logs, and other information that has already been used to model the reservoir and formation. Moreover, the arrangement of wells (10) for observation and impulse are selected for providing the best correlations from a cluster of wells in the reservoir.

Once the layout for the system (100) is chosen, operators then install downhole pressure devices (110) in the observation wells and pressure couple them to the hydrocarbon or water reservoir (Block 154). As noted previously, operators use a suitable conveyance, a wireline, a tractor, and a pre-selected wireline interconnect length to install the downhole pressure devices (110), which can be set temporarily in the wells. The devices (110) may need sufficient memory and battery for the duration of the test.

Prior to a reservoir pressure impulse event, operators test the system (100) by measuring a pressure reference value with the downhole devices (110) coupled to the reservoir (Block 156). Additionally, operators perform reservoir simulation to determine if magnitude of possible reservoir responses will be within gauge resolution and error limits of the system (100).

Once the system (100) is set, operators initiate the impulse at the impulse location (I) (Block 158). To do this, operators affect one well (i.e., 10A) in the reservoir with a large pressure impulse during oilfield operations related to drilling, production, exploration, or testing. For example, the impulse may be from an injection of material added to the reservoir or may be from production (removal) of materials from the reservoir.

During this time and for a period after the impulse, the downhole pressure devices (110) obtain reservoir pressure data at the observations locations (O_(A-C)) (Block 160). The impulse preferably continues until a real-time response is obtained at the remote devices (110). Once obtained, the responses from the devices (110) can be transmitted real-time to a central unit (140) and/or may be recorded in memory of the devices (110) for later retrieval.

When the monitoring period ends, operators remove the downhole pressure devices (110) from the wells (Block 162). As described in FIG. 1, for example, operators can reconnect interconnects and pull the devices (110) from well with wireline, or operators can fish the devices (110) out of the wells if set as memory tools. Either way, the system (100) does not require any permanent hardware to be left in the wells.

Finally, operators process the pressure responses from the observation locations (O_(A-C)) (Block 164). Processing can use a numerical simulator to model characteristics of the reservoir and can be based on input data, including well locations, pressure responses, depths, known fluid types, seismic data, previous production or logging data, etc. In general, the processing is based on the measured pressure levels, the type of impulse used, the locations/distances/orientations of the observation wells in reservoir, the time between impulse and responses, and other variables depending on the implementation. The pressure responses may need to be normalized based on the reference pressure value initially obtained and based on any time lag related to transmission delays in the system (100).

The processed data is then interpreted to define or confirm the reservoir's extent, boundaries, communication, and reserve estimates. For example, operators can use the processed data to determine the pressure distribution in the reservoir and characterize barriers, faults, pools, permeable zones, communication paths, obstructions, and other features of the reservoir. In this way, the system (100) directly monitors and measures actual reservoir behavior for effective and efficient reservoir understanding and optimization. In other words, the system (100) obtains direct pressure measurements that are not inferred from other information. Therefore, the resulting characterization of the reservoir is based directly on the fluid pressure as measured in the reservoir and not just by an inferred model obtained through imaging techniques generally used in the art.

B. Examples

Below are several multi-well examples in which the disclosed system 100 and techniques can be used to characterize features of the reservoir.

1. Reservoir Connectivity

FIG. 3A shows a plan view of a first arrangement 100A having various observer wells (O₁₋₄) surrounding an impulse well (I) for characterizing features of a reservoir. The impulse from the impulse well (I) emanates outward to the observations wells (O₁₋₄), where the changes in formation pressure can be detected. As can be seen, the observations wells (O₁₋₄) are located at various distances (d₁₋₄) from the impulse well (I), and the pressure responses detected at the observations wells (O₁₋₄) will depend on the time and distance between the impulse well (I) and the observations wells (O₁₋₄). This information can then be used to characterize features of the reservoir.

For example, FIG. 3B shows an example graph 200A of reservoir pressure data versus time from the first arrangement 100A. In this graph, a single impulse (P₀) is produced in the reservoir using production at the impulse well (I). Thus, the reservoir pressure dips during the single production impulse. (Injection would produce a pressure spike.) The pressure impulse emanates from the impulse well (I) and travels the distances (d₁₋₄) to the observations wells (O₁₋₄).

Eventually, the observations wells (O₁₋₄) record pressure drops at various times (t₁₋₄) and with various magnitudes (P₁₋₄). Processing can then use the magnitudes (P₁₋₄), times (t₁₋₄), and distances (d₁₋₄) involved to measure reservoir features such as the connectivity of the reservoir, the reservoir's path length, the reservoir's extent, and the reservoir's fluid type based on the time of pressure propagation from impulse to observation.

The pressure responses from the observation wells (O₁₋₄) can be combined with existing seismic data, information from formation cores of the wells, and reservoir simulations, as well as other information to further enhance the characterization of the reservoir. Additionally, one or more of the observations wells (O₁₋₄) can be selected as the impulse well so that another impulse can be performed and measured from other perspectives in the reservoir to further characterize it.

2. Reservoir Barrier

FIG. 4A shows a plan view of a second arrangement 100B of adjacent wells in a reservoir having various observations wells (O₁₋₄) and an impulse well (I). In this example, a barrier 20 exists in the reservoir, and operators may not know of this barrier 20, or operators may not know the full extent of this reservoir or whether any communication paths exist through the barrier 20. Information about the barrier 20 may be obtained from seismic imaging or other techniques. Yet, the seismic image may not characterize how the barrier affects the reservoir's connectivity, communications, pressure distribution, etc.

Accordingly, operators use the disclosed system 100 and techniques to determine information about this reservoir and the barrier 20. For example, the graph 200B of FIG. 4B shows a single impulse (production shown) and observed pressure responses at two of the observation wells (O₁₋₂). Pressure responses are not observed at the other observations wells (O₃₋₄). Processing this data, operators can determine the connectivity and extent of the reservoir as well as confirm the existence and extent of the barrier 20. In this case, there appears to be no communication across the barrier 20.

3. Reservoir Pools

FIG. 5A shows a plan view of a third arrangement 100C of adjacent wells in a reservoir having various observations wells (O₁₋₂) and an impulse well (I). In this example, the reservoir has isolated pools 30 and 35. Operators may not know these pools 30 and 35 exist, or operators may not know the full extent of the reservoir or whether any communication paths exist between the pools 30 and 35.

Using the disclosed system 100 and techniques, operators can determine information about this reservoir and the pools 30 and 35. For example, the graph 200C in FIG. 5B shows a single impulse (production shown) and observed pressure responses at one of the observation wells (O₁). A pressure response is not observed at the other observation well (O₂). In addition to connectivity and extent of the reservoir, operators processing this data can determine that the two pools 30 and 35 are not connected, although they may have same pressure and fluid characteristics.

In a fourth arrangement 100D of FIG. 6A, however, two pools 30 and 35 have communication therebetween. As shown in graph 200D of FIG. 6B, a single impulse (production shown) and observed pressure response (P₁) at one of the observation well (O₂) is obtained at a first time (t₁). Later, a pressure response (P₂) of one magnitude is observed at the other observation well (O₂) at a subsequent time (t₂), and then another pressure response (P₃) of lesser magnitude is observed at the other observation well (O₂) at an even later time (t₃). In addition to connectivity and extent of the reservoir, operators processing this data can determine that the two pools 30 and 35 are connected by at least two paths 32/34. The time difference (t₂-t₃) between responses (P₂-P₃) can then be used to define the different lengths of the paths 32/34. Knowledge of these paths 32/34 can then be used to plan injection operations or the like to better extract fluid from the reservoir with the existing wells.

4. Reservoir Layers

Previous examples show how two-dimensional distances between the impulse and observation locations can be used to characterize a reservoir. A third dimension of depth can also be used in the measurements. For example, FIG. 7A shows a side view of a fifth arrangement 100E of adjacent wells (Wells A, B, & C) in a reservoir. A first well (Well A) has an observation location (O_(A)) at a first depth, a second well (Well B) has a second observation location (O_(B)) at a second depth, and a third well (Well C) has an observation location (O_(c)) at a third depth. The second well (Well B) also has an impulse location (I_(B)) at a depth in this well.

In this example, the reservoir has a dome 40 containing a lower layer 42 of water, an intermediate layer 44 of oil, and an upper layer 46 of gas. The observation locations (O_(A-C)) and impulse location (I_(B)) may be positioned at their different depths in the various layers 42, 44, and 46.

Depending on the circumstances, operators may not know the full details of these layers 42, 44, and 46 or may need to determine changing characteristics between them. Accordingly, operators can use the disclosed system 100 and techniques to determine information about these layers 42, 44, and 46. For example, the graph 200E in FIG. 7B shows a single impulse (i.e., production at the impulse location I) and observed pressure responses at observation locations (O_(A-C)). For example, after the impulse (production shown), a pressure response (P₁) for one location (O_(B)) is observed at a first time (t₁), a smaller pressure response (P₂) for another location (O_(C)) is observed at a later time (t₂), and an even smaller pressure response (P₃) for the last location (O_(A)) is observed at time (t₃).

The times observed can be synchronized accurately using GPS or other techniques. Operators processing the data can then determine the extent of fluid types using the different speed of pressure wave propagation in the layers 42, 44, and 46 based on the pressure response lags and the like. From this, operators can identify the effectiveness of injection operations, identify fluid level contacts, and reservoir connectivity.

5. Reservoir Obstructions

In FIG. 8A, a sixth arrangement 100F of adjacent wells in a reservoir has various observation wells (O₁₋₃) and an impulse well (I) as well as an obstruction 50 with communication paths 52/54 therearound. Operators may not know the obstruction 50 exists, or operators may not know the full extent of the reservoir or whether any communication paths exist around the obstruction.

Accordingly, operators can use the disclosed system 100 and techniques to determine information about the obstruction 50. As shown in graph 200F of FIG. 8B, a single impulse (production shown) at the impulse well (I) and observed pressure response at observation wells (O₁₋₂) are obtained at different times (t₁₋₂). Later, separate pressure responses are observed at the other observation well (O₃) at subsequent times (t₃₋₄). In addition to connectivity and extent of the reservoir, operators processing this data can determine that the reservoir has communication around the obstruction 50 by at least two paths 52/54. The time difference (t₂-t₃) between the separate responses (O_(3A), O_(3B)) can then be used to define the different lengths of the paths 52/54.

C. Reservoir Well Spacing

FIG. 9A shows a plan view of a seventh arrangement 100G of adjacent wells in a reservoir having various observation wells (O₁₋₇) and an impulse well (I). FIG. 9B shows an example graph 200G of reservoir pressure versus time. After the impulse (production shown) at the impulse well (I), some of the observation wells (O₁₋₆) monitor pressure responses at various time lags without much difference. From this, operators may seek to optimize in field drilling to drain reservoir and conclude there are too many wells. For example, operators can determine that most of the wells are unnecessary to drain the reservoir. Optimal spacing for the reservoir may be the distance between the impulse well (I) and the farthest observation well (O₇) and not the current spacing of all the other wells (O₁₋₆) relative to the impulse well (I).

The foregoing description of preferred and other embodiments is not intended to limit or restrict the scope or applicability of the inventive concepts conceived of by the Applicants. In exchange for disclosing the inventive concepts contained herein, the Applicants desire all patent rights afforded by the appended claims. Therefore, it is intended that the appended claims include all modifications and alterations to the full extent that they come within the scope of the following claims or the equivalents thereof. 

1. A reservoir characterization method, comprising: deploying a plurality of downhole pressure devices in a plurality of wells penetrating a reservoir; initiating at least one pressure impulse at at least one impulse time in at least one of the wells penetrating the reservoir; obtaining pressure responses at response times with the downhole pressure devices in the wells; communicating the at least one impulse time, the pressure responses, and the response times to a central unit; processing the pressure responses and the response times with the central unit; and characterizing the reservoir based on the processing.
 2. The method of claim 1, wherein deploying the downhole pressure devices comprises coupling tools in the wells for measuring pressure of formations surrounding the wells.
 3. The method of claim 1, further comprising: obtaining reference pressure measurements with the downhole pressure devices in the absence of the at least one impulse; and scaling the pressure responses with the reference pressure measurements.
 4. The method of claim 3, further comprising determining if magnitudes of pressure responses of the downhole pressure devices fall within a limit by performing reservoir simulation.
 5. The method of claim 1, wherein initiating the at least one pressure impulse comprises performing one or more of: producing a pressure drop in the at least one well; performing production from the at least one well producing a pressure spike in the at least one well; drilling in the at least one well with drilling fluid; injecting treatment fluid in the at least one well; and performing a test in the at least one well.
 6. The method of claim 1, wherein communicating the pressure responses and the response times to the central unit comprises recording the pressure responses and the response times in memory of the downhole pressure devices.
 7. The method of claim 1, wherein communicating the pressure responses and the response times to the central unit comprises transmitting the pressure responses and the response times in real time from the downhole pressure devices to the central unit.
 8. The method of claim 1, wherein communicating the at least one impulse time, the pressure responses, and the response times to the central unit comprises transmitting one or more of the at least one impulse time, the pressure responses, and the response times in real-time to the central unit, or transferring one or more of the at least one impulse time, the pressure responses, and the response times from memory to the central unit.
 9. The method of claim 1, wherein processing the pressure responses and the response times with the central unit comprises one or more of: comparing magnitudes of the pressure responses; determining speeds of pressure wave propagation based on the response times and based on distances between the at least one impulse and the downhole pressure devices; determining connectivity of the reservoir between the wells; determining a path length of the reservoir; determining an extent of the reservoir; determining a fluid type of the reservoir; and determining distribution of pressure in the reservoir.
 10. The method of claim 1, wherein processing comprises combining the response pressures and the response times with one or more of: depths of the downhole pressure devices, seismic data of the reservoir, information from formation cores of the wells, locations of the wells having the downhole pressure devices, known fluid types in the wells, previous production data of the wells, previous logging data of the wells, and reservoir simulations.
 11. The method of claim 1, further comprising: initiating at least one pressure impulse at at least one impulse time in another one of the wells penetrating the reservoir; and repeating the acts of obtaining, communicating, processing, and characterizing the reservoir.
 12. The method of claim 1, wherein characterizing the reservoir comprises characterizing one or more of a barrier, a fault, a pool, a permeable zone, a communication path, an extent, a fluid contact, and an obstruction of the reservoir.
 13. The method of claim 1, wherein characterizing the reservoir comprises: determining that at least one of the downhole pressure devices has failed to obtain at least one of the pressure responses; and characterizing an obstruction in the reservoir between the at least one well and the at least one downhole pressure device.
 14. The method of claim 1, wherein characterizing the reservoir comprises: determining that at least a first of the downhole pressure devices in a first of the wells has obtained at least one of the pressure responses; determining that at least a second of the downhole pressure devices in a second of the wells has failed to obtain one of the pressure responses; and characterizing the reservoir as having a first pool associated with the first well and having a second pool associated with the second well.
 15. The method of claim 1, wherein characterizing the reservoir comprises: determining that at least one of the downhole pressure devices in a first of the wells has obtained a first magnitude of the pressure responses within a first time interval; determining that the at least one downhole pressure device in the first well has obtained a second magnitude of the pressure responses within a second time interval; and characterizing the reservoir as having a first communication path for the first time interval and a second communication path for the second time interval.
 16. The method of claim 15, wherein the second magnitude is less than the first magnitude.
 17. The method of claim 1, wherein deploying the downhole pressure devices in the wells of the reservoir comprises deploying at least two of the downhole pressure devices at different depths than the at least one pressure impulse.
 18. The method of claim 17, wherein processing comprises calculating speeds of pressure wave propagation for the pressure responses of the at least two downhole pressure devices.
 19. The method of claim 18, wherein characterizing the reservoir comprises determining a characteristic of one or more layers in the reservoir based on the calculated speeds of pressure wave propagation.
 20. The method of claim 17, wherein one of the at least two downhole pressure devices is deployed in a same well as the one in which the at least one pressure impulse is initiated.
 21. The method of claim 17, wherein one of the at least two downhole pressure devices is deployed in a different well from the one in which the at least one pressure impulse is initiated.
 22. A reservoir characterization system, comprising: a plurality of downhole pressure devices deploying in a plurality of wells penetrating a reservoir, the downhole pressure devices each obtaining pressure responses at response times in response to at least one pressure impulse initiated at at least one impulse time in at least one of the wells penetrating the reservoir; communication equipment communicating the at least one impulse time, the pressure responses, and the response times of the downhole pressure devices; and processing equipment communicatively coupled to the communication equipment and receiving the at least one impulse time, the pressure responses, and the response times, the processing equipment processing the pressure responses and the response times and characterizing the reservoir based on the processing. 